Note: Descriptions are shown in the official language in which they were submitted.
REMOTE PREHEAT AND PAD STEAM GENERATION
FIELD OF THE DISCLOSURE
[0001] The invention relates to methods and systems for generating
steam for
downhole use.
BACKGROUND
[0002] Steam Assisted Gravity Drainage or "SAGD" (pronounced sag-
DEE) is an
enhanced oil recovery technology for producing heavy crude oil and bitumen. It
is an advanced
faun of steam stimulation in which a pair of horizontal wells are drilled into
the oil reservoir, one
a few meters above the other. High-pressure steam is continuously injected
into the upper wellbore
to heat the oil and reduce its viscosity, causing the heated oil and any
condensed water to gravity
drain into the lower wellbore, where it can be pumped to the surface.
[0003] Generally speaking, high quality, high temperature, and high
pressure steam
is required. The SAGD process may call for 100% quality, 7,000 ¨ 11,000 1(13A
and 238-296 C
temperature steam. Considering oil production volume, and the fact that at
least 3 barrels of water
are needed for every barrel of oil, the water requirements for SAGD are
immense, although water
recycling can reduce water consumption considerably.
[0004] In addition to requiring large amounts of water, the cost of
steam generation
is a major contributor to the cost of oil production. The fuel needed to heat
water to steam and the
transportation of high quality steam to the well pad all contribute to high
costs. In addition to the
cost of steam generation, each barrel of oil produced in SAGD is co-produced
with 3-5 barrels of
water, which then must be separated from the oil, and treated before
recycling. Water treatment
facilities further contribute to cost.
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Date Recue/Date Received 2023-01-05
[0005] Steam can be produced in various ways, including conventional
drum
boilers, direct steam generators, and once through steam generators. If the
water is sufficiently
cleaned, e.g., with evaporator technology, a drum boiler can be used, where
the water runs through
the boiler more than once, and steam is collected at the top in a drum for
distribution, while
condensate travels back through the boiler for reheating.
[0006] However, the "once-through steam generator" or "OTSG" is more
commonly used to provide the steam for SAGD, and other steam based enhanced
recovery
methods such as cyclic steam generation or "CSS," because recycled water
typically is not clean
enough for conventional boiler use.
[0007] The OTSG features a single pass of water through the
generator coil, where
the feedwater is heated and eventually vaporized by a countercurrent of e.g.,
hot gas produced by
the furnace. Regardless of what boiler technology is used, usually the boiler
feedwater is preheated
by heat exchange with e.g., a hot combustion gas, usually flue gas, or a hot
fluid, such as the hot
produced fluids. The recapture of otherwise waste heat reduces the overall
energy needed to make
steam.
[0008] The preheated feedwater is then converted to steam in the
OTSG by the heat
radiated from the furnace, resulting in about 80% quality steam, i.e. the
weight ratio of water to
steam at the outlet of the generator is about 1:4. The 80% quality steam then
goes through a series
of liquid-steam separators (also called "flash drums") to increase the steam
quality of OTSG.
[0009] Although it is possible to further heat (superheat) the low
quality steam to
generate 100% steam, this increases fouling of the OTSG as all of the water
evaporates and leaves
significant solids behind to foul the heat transfer surfaces. Thus, the
relatively low steam quality
helps to maintain wet conditions in the OTSG tubes in order to reduce fouling
and scaling.
[0010] The water remaining once the low quality steam and water are
separated is
called "blow-down" water and has fairly high levels of dissolved organic
compounds. Typical
blow-down levels are about 20%. Blowdown can be reused in the OTSG, thus
saving on overall
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Date Recue/Date Received 2023-01-05
water usage, but clean boiler feedwater is preferred, because the organics
contribute to fouling of
the boiler. Thus, blowdown water must be treated before reuse.
[0011] There are OTSG designs that include a preheat section,
typically called an
"ecomomizer", a vaporizer or "radiant" section, and a "superheater" section so
that a high quality
steam can be generated within a single OTSG unit. However, these units are
quite large, expensive,
and as noted, superheating steam leads to fouling unless very clean feed-water
is used, which is
not usually practical given the imperative to reuse water.
[0012] Typically, the OTSG is located at the central processing
facility (CPF) and
the steam is transported to the well pad for injection because the boiler and
preheat equipment is
too large to be placed at the well pad. However, the steam-lines that connect
the CPF boilers to
the pads are costly and limited in length due to pressure loss and steam
condensation issues. This
contributes further to cost.
[0013] Therefore, there is the need for an improved steam generation
methods that
reduce the cost of steam production, e.g., by eliminating the need for steam-
lines, but without
overcrowding the well pad.
SUMMARY
[0014] The present disclosure provides a method of reducing the need
for steam
lines, but without overcrowding the well pad.
[0015] The basis of the disclosure is a process that reduces the
thermal duty and,
consequently, the size and footprint of well pad boilers. This is accomplished
by preheating the
well pad boiler feed water to as high a temperature as possible without any
vaporization at the CPF
and transporting the preheated water to the well pads. Because the feedwater
arrives at the well
pad at a higher temperature, less energy is needed to convert that feedwater
into steam. This
reduces the required heat transfer surface area within the boiler and
consequently reduces the size
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Date Recue/Date Received 2023-01-05
and footprint of that boiler. It also reduces the fuel gas and combustion air
demand, minimizing
utility requirements at the well pads.
[0016] Any steam generator technology can be used at the well pad,
including
water tube drum boilers, fire tube drum boilers, direct steam generators, oxy-
fired direct steam
generators, OTSG units, and the like. However, the smaller footprint is
desired, and thus a single
water tube drum boiler may be preferred. Drum boilers also offer the advantage
of less blow down,
thus reducing the flow rate of blow down that needs to be transferred from the
pads to the CPF.
Evaporative water treatment is relatively costly, but can be offset by the
lower drum boiler versus
OTSG boiler costs. However, any steam generator can be used.
[0017] The preheated water would ideally be heated to a temperature
within 5-
30 C, preferably 10-25 C of the boiling point at the well pad boiler operating
steam pressure.
Subcool is desired to minimize the likelihood of flashing in the lines. A
preferred subcool is 10-
20 C or about 10 C.
[0018] SAGD surface facilities include water-preheating
capabilities, and in most
cases, preheat OTSG feedwater with heat from produced fluids, OTSG blow-down,
warm glycol,
and other hot streams. However, these heat recovery systems only enable
preheat temperatures of
140-180 C. If supplemental preheating is required, it will need to be provided
by a fired heater,
boiler, or other high temperature heat source. Several embodiments are
described herein.
[0019] The first embodiment applies to processes that include
boilers both at the
CPF and at the well pads. In these applications, the CPF boilers provide the
necessary preheating.
In one option, the well pad boiler feed-water is heated in a coil within an
OTSG economizer
section, where the OTSG is located at the CPF. This uses some of the thermal
duty of the OTSG
to provide feed water preheating, but requires a customized OTSG that can
generate steam from
one water source and preheat water from a second water source.
[0020] In the second option, the well pad boiler feed-water is
heated by heat
exchange with the hot OTSG blow-down. This enables the use of existing OTSGs,
but will impact
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Date Recue/Date Received 2023-01-05
the OTSG heat recovery system because blow-down heat that would otherwise
preheat OTSG
feed-water is now used to heat pad boiler feedwater. The first and second
options may be employed
in combination or separately.
[0021] A possible limitation of this embodiment is that it requires
some steam
generation at the CPF, which implies that the preheat temperature may be
limited by the ratio of
well pad to CPF steam generators. This can be addressed by preheating the feed
water in a
dedicated fired heater placed at the CPF in some embodiments. In some example
embodiments,
the fired heater provides supplemental heating of the feedwater after it is
initially heated with waste
heat (glycol and produced fluids) at the CPF. This is a more flexible
configuration, as it does not
require steam generation at the CPF.
[0022] In some embodiments, an alternate heat source to a fired
heater is a gas
turbine that generates on-site power. Gas turbines produced exhaust gas at
temperatures of 350-
550 C. This heat is often recovered in heat recovery steam generators (HRSGs),
but in this
embodiment, could provide supplemental water preheat.
[0023] The invention includes any one or more of the following
embodiments, in
any combination thereof:
[0024] A method of generating steam for use in a well to produce oil
comprising
heating a boiler feedwater located at a central processing facility (CPF) to
produce heated boiler
feedwater (HBFW), transporting the HBFW, which has a subcool of 5-30 C or 10-
20 C, to a well
pad via hot water lines, feeding the HBFW into a well pad boiler located at
the well pad, and
converting the HBFW to steam in the well pad boiler. The steam is then
injected into a well located
at said well pad to produce oil.
[0025] The initial heating at the CPF can be performed by a gas
burning water
heater, a gas burning turbine heater that produces electricity and HBFW, a
once through gas
generator (OTSG), or combinations thereof. The well pad boiler can be a water
tube drum boiler.
Date Recue/Date Received 2023-01-05
[0026] The initial heating at the CPF can also be preceded by a
preheating step that
preheats the boiler feedwater before it is feed into the heater at the CPF.
The HBFW can also be
preheated before being heated by the well pad boiler. In some embodiments,
both preheating steps
occur.
[0027] A steam generator system for oil production having a water
heater located
at a CPF to heat boiler feedwater to HBFW, where the HBFW has a subcool of 5-
30 C, a hot water
line for transporting the HBFW from the CPF to a steam generator at a well
pad, and a steam line
for injecting steam into a well at the well pad. The heaters and lines are all
fluidly connected.
[0028] The steam generator system can have a heat exchanger located
at the CPF
for preheating said boiler feedwater. The steam generator system can have a
heat exchanger located
at the well pad for preheating said HBFW. Alternatively, a heat exchanger can
be located at both
the CPF and well pad for preheating the boiler feedwater and HBFW,
respectively.
[0029] The steam generator at the well pad can be a water tube drum
boiler. The
water heater at the CPF can be a gas fired water heater, natural gas fired
water heater, a gas burning
turbine heater that produces electricity and HBFW, a once through gas
generator (OTSG), or
combinations thereof
[0030] An improved method of producing steam for oil production, the
method
including heating boiler feedwater in a steam generator at a CPF, and
transporting the steam in a
steam line to a well pad for downhole use, the improvement being heating
boiler feedwater in a
water heater located at a CPF to 5-30 subcool, transporting the heater boiler
feedwater at 5-30 C
subcool to a steam generator located at a well pad, and further heating the
heated boiler feedwater
in the steam generator to produce steam for downhole use.
[0031] An improved method of producing steam for oil production, the
method
including heating boiler feedwater in a steam generator at a CPF, and
transporting the steam in a
steam line to a well pad for downhole use, the improvement comprising heating
boiler feedwater
in a water heater located at a CPF to 10-20 C subcool, transporting the boiler
feedwater at 10-
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Date Recue/Date Received 2023-01-05
20 C subcool to a water tube drum steam generator located at a well pad, and
heating the boiler
feedwater in the water tube drum steam generator to produce steam for
injection into a well located
at said well pad.
[0032] An improved method of producing steam for oil production, the
method
includes heating boiler feedwater in a steam generator at a CPF, and
transporting the steam in a
steam line to a first well pad for downhole use, the improvement comprising
heating boiler
feedwater in a water heater located at a CPF to 10-20 C subcool, transporting
the boiler feedwater
at 10-20 C subcool to a second well pad, preheating the 10-20 C subcooled
boiler feedwater in a
heat exchanger located at the second well pad, converting the preheated boiler
feedwater to steam
in a water tube drum boiler located at the second well pad, and injecting the
steam into a well
located at the second well pad.
[0033] As used herein, a "water tube drum boiler" is a drum based
steam generator
having 1-4 drums, which function to collect the steam generated in the water
tubes and acts as a
phase-separator for the steam/water mixture. Water is routed back through the
boiler.
[0034] As used herein, a "Once-Through Steam Generator" or "OTSG" is
a
specialized type of heat recovery steam generator without boiler drums.
[0035] The OTSG without a superheating section typically produces a
"wet" steam
that consists of about 77% steam and 23% water. The water that is separated
from the steam is
known as "blowdown water." It typically has concentrated levels of TOC and
thus is quite dirty.
[0036] As used herein, "economizer" means the device for reducing
energy
consumption in a steam-generating operation by preheating feedwater.
Typically, an economizer
is in the form of heat exchanger where the thermal energy is transferred from
a high temperature
fluid (e.g., steam condensate, flue gas or other waste heat source) to the
feedwater such that less
energy is required to vaporize it. Economizers are mechanical devices intended
to reduce energy
consumption or to perform another useful function such as preheating a fluid.
In boilers,
economizers are heat exchange devices that heat fluids, usually water, up to
but not normally
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Date Recue/Date Received 2023-01-05
beyond the boiling point of that fluid. Economizers are so named because they
can make use of
the enthalpy in fluid streams that are hot, but not hot enough to be used in a
boiler, thereby
recovering more useful enthalpy and improving the boiler's efficiency. They
are fitted to a boiler
and save energy by using e.g., the exhaust gases from the boiler or other hot
plant fluids to preheat
the cold feedwater. It has been reported that approximately 35 to 50% of the
total absorbed heat
in OTSG is transferred in the economizer.
[0037] As used herein, "radiant section" means the section in a
steam generator
where the heating of feedwater is primarily achieved by radiant heat transfer.
[0038] As used herein, "subcooling" is any temperature of a liquid
or solid below
its saturation temperature. Saturation is simply the term used to describe the
point where a change
of state in a substance is taking place. For water at sea level, the boiling
temperature is 212 F or
100 C. Therefore, the saturation temperature is 212 F or 100 C. A subcool of
10 C or 20 C will
protect the lines from steam flashing if the pressure is reduced.
[0039] "Flash steam" is the name given to the steam formed from hot
condensate
when the pressure is reduced. The transport of subcooled water will prevent
steam flashing, and
thus the erosion and damage that can occur on flashing.
[0040] As used herein, a "hot water line" is rated for hot water
use, but not for
steam use. Steam lines are typically subject to much stricter requirements due
to the high-pressure
steam they carry. They are thus more costly.
[0041] The use of the word "a" or "an" when used in conjunction with
the term
"comprising" in the claims or the specification means one or more than one,
unless the context
dictates otherwise.
[0042] The term "about" means the stated value plus or minus the
margin of error
of measurement or plus or minus 10% if no method of measurement is indicated.
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Date Recue/Date Received 2023-01-05
[0043] The use of the term "or" in the claims is used to mean
"and/or" unless
explicitly indicated to refer to alternatives only or if the alternatives are
mutually exclusive.
[0044] The terms "comprise", "have", "include" and "contain" (and
their variants)
are open-ended linking verbs and allow the addition of other elements when
used in a claim.
[0045] The phrase "consisting of' is closed, and excludes all
additional elements.
[0046] The phrase "consisting essentially of' excludes additional
material
elements, but allows the inclusions of non-material elements that do not
substantially change the
nature of the invention.
[0047] The following abbreviations are used herein:
ABBREVIATION TERM
ATM Atmosphere
BFW Boiler feed-water
CAPEX Capital expenditures
CCS Cyclic steam stimulation
CPF Central processing facility
DOC Dissolved organic carbon
DSG Direct steam generator (aka DCSG for direct contact
steam
generator)
NG Natural gas
OPEX Operating expenditures
OTSG Once-through steam generator
SAGD Steam-assisted gravity drainage
TDS Total dissolved solids
TOC Total organic carbon
Is Saturation temperature
TSS Total suspended solids
WLS Warm-lime softener
BRIEF DESCRIPTION OF THE DRAWINGS
[0048] FIG. 1A. provides one example of a water tube drum boiler.
[0049] FIG. 1B. illustrates the operating principle for an OTSG.
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Date Regue/Date Received 2023-01-05
[0050] FIG. 2. One embodiment of the disclosed method using
preheated well pad
steam generator concept, with heat provided by steam generators at CPF.
[0051] FIG. 3. Another embodiment of the disclosed method using
preheated well
pad steam generator concept, with heat provided by fired heater at CPF.
[0052] FIG. 4. Another embodiment using preheated well pad steam
generator
concept, with heat provided by gas turbine exhaust gas.
DETAILED DESCRIPTION
[0053] We investigated various alternatives for reducing the cost of
steam
generation without overcrowding the well pad, and herein describe a method
wherein water is
heated at the CPF to within 5-30 C or 10-20 C of the boiling point at the
operating pressure of the
OTSG or other steam generator.
[0054] The subcooled water is transported to the well pad, where it
is converted to
steam in an OTSG, water tube drum boiler, or other boiler. If desired, the
OTSG can be equipped
with an economizer to capture waste heat from the blow-down water, produced
fluids or waste
flue gas. Because the feedwater is significantly preheated before transport to
the OTSG, less fuel
is used to create the steam. Further, the lines need only be qualified for hot
fluid transport, not
steam transport and thus need not meet the elevated temperature tensile tests
and other high
standards required for high pressure steam lines. In some embodiments, a
distance of at least 100
meter or at least 1 kilometer separates the CPF from the well pad with the
steam generator.
[0055] FIG. 1A shows one embodiment of a water tube drum boiler
100A. The
water tube drum boiler 100A may be referred to as a "fire tube drum boiler"
which has hot gas in
the tube. The water tube drum boiler 100A comprises a feedwater drum 101A.
Water 102A may
be fed into the feedwater drum 101A. The feedwater drum 101A may be connected
to a steam
drum 104A by one or more water tubes 103A and a downcomer tube 108A. Fuel 112A
may be
burned by a fuel burner 113A, creating hot gas which boils water in the water
tubes 103A. The
Date Recue/Date Received 2023-01-05
heated water/steam mixture may then rise into a steam drum 104A. The steam
drum 104A may
comprise a safety valve 107A. Saturated steam 105A may pass through a
superheater 109A and
exit through a saturated steam outlet 110A as superheated steam 111A. Water at
the bottom of the
steam drum 104A may be returned to the feedwater drum 101A via the downcomer
tube 108A.
Exhaust gases 114A may be used to pre-heat combustion air blown into the
burners, and/or to
warm the feedwater supply. FIG. 1B shows one embodiment of an OTSG 100B. In
one
embodiment, inlet feedwater follows a continuous path. The absence of drums
allows for quick
changes in steam production and fewer variables to control, and is ideal for
cycling and base load
operation. In the illustrated embodiment, feedwater enters from inlet 101B.
The gas flow 102B
may be in the opposite direction to that of the water flow. Steam may be
generated and exits at
outlet 103B.
[0056] FIG. 2 shows one embodiment of the disclosure wherein OTSG
1000 is at
the CPF and functions (in part) to preheat water for a drum boiler 1500 at the
well-pad. Two
options are thus shown in FIG. 2 and may be employed in combination as
illustrated or separate.
First, where the pad boiler feedwater is heated in a coil within an OTSG
economizer section. This
uses some of the thermal duty of the OTSG to provide feed water preheating,
but requires a
customized OTSG that can generate steam from one water source and preheat
water from a second
water source. In the second option, the well pad boiler feedwater is heated by
heat exchange with
the hot OTSG blowdown. This enables the use of existing OTSGs, but will impact
the OTSG heat
recovery system because blowdown heat that otherwise preheats OTSG feedwater
is now used to
heat pad boiler feedwater. One or the other or even both systems could be
used.
[0057] In more detail, air entering the OTSG via line 190 is
preheated in heat
exchanger 1060. Fuel enters the burner 1010 via line 180, mixes with preheated
air from line 190
and burns to create hot gas, which travels to the other end of the OTSG
heating fluid in coils 100
and 101. The hot gas pathway is from the burners to the stack. Coil 101
accepts boiler feedwater
via line 130, which is preheated with blowdown water and coil 100 accepts
boiler feedwater via
line 110. The routing of these lines is of course variable, as noted above,
depending on which
option(s) is/are implemented. Hot gas that has given its latent heat to the
fluid in the coils 100,
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Date Recue/Date Received 2023-01-05
101 can be routed back to heat exchanger 1060 if desired. Alternatively, it
can be routed to the
stack.
[0058] Hot fluid exiting OTSG coils is routed to separator 1030 via
line 150, where
steam is separated from blow-down water. Steam is routed via line 160 to where
its is needed, e.g.,
to the well pad for injection, and blowdown water run through line 170 to heat
exchanger 1050 to
warm incoming boiler feedwater via line 130. Preheated water can be routed via
line 140 and
pump 1040 to the well pad for use in drum boiler 1500.
[0059] Subcooled water enters the drum boiler 1500 at the well pad
via line 140, is
turned into steam in drum boiler 1500 and the steam routed to the well via
steam line 240. Fuel
enters a burner 1530 of drum boiler 1500 via fuel line 230, and heated air via
line 220. The air
from line 210 was preheated in air preheater (heat exchanger) 1510 using the
exiting flue gas.
[0060] FIG. 3 shows yet another embodiment, using a natural gas (NG)
fired water
heater 2000 at the Central Processing Facility (CPF) to preheat water for the
steam generator at
the well pad, in this case water tube drum boiler 2500. If desired, clean
water (e.g., from an
evaporator) via line 210 can be preheated with heat exchanger 2060, e.g, by
hot glycol originating
from e.g., the CPF hot glycol system (i.e. glycol that has been heated in
various units that cool
process streams). The water can be further heated using produced fluids from
the reservoir after
separation in a pad separator 2070, using gas heat exchanger 2030 via line 216
(comprising
produced gas) for a first portion 213 of the water and liquid heat exchanger
2050 via line 215
comprising produced liquid (bitumen/water) for a second portion 211 of the
water.
[0061] The somewhat cooled produced liquid is then routed to a
separator (not
shown) for separation into crude oil, routed to storage or shipment, and
produced water, which is
routed to water treatment facilities, in this instance suggesting an
evaporator, but possibly
including one or more of filtration, precipitation, warm lime softener, an
advanced oxidation
process, and the like.
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Date Recue/Date Received 2023-01-05
[0062] Prewarmed water is routed via line 214 to a water heater
2000, e.g, a NG
fired water heater with burner 2010 fed by air and fuel lines. Hot water is
transported to the well
pad by pump 2550. If desired water can also be heated in heat exchanger 2560
by blowdown water
fed by line 219. Blowdown water then travels by line 220 to some water
treatment facility (e.g.,
to one or more evaporators).
[0063] Preheated water enters drum boiler 2500 via line 218. Drum
boiler 2500 is
heated by burner 2510 fed by air line 224 and fuel line 223. Air line 224 can
be preheated in air
preheater 2540, which is heated with hot flue gas exiting the drum boiler 2500
via line 225.
[0064] Steam exits the drum boiler 2500 via lines 220 and 222
(comprising wet
steam) to separator 2520 which sends water back to the drum boiler 2500 via
line 220 and pump
2530 and steam to the well via line 221. The steam in lines 220 appears to be
running in two
directions due to the internal recirculation in water tube drum boilers. Drum
boilers inherently
have high internal recirculation rates, i.e. only 10-20% of the feedwater is
evaporated in boiler.
The 10-20% quality steam enters a drum to separate steam/water, and the water
is recirculated.
[0065] FIG. 4 shows yet another possible embodiment, wherein a gas
turbine 3010
generates heat and electricity (not shown) for use on site, by burning air
routed through compressor
3030 in combustor 3020 fed by fuel line 315 and air line 314. The burning fuel
rotates the turbine
3010 and the hot gases used to preheat water in heat exchanger 3000 (e.g., NG-
fired), and exit via
turbine exhaust line 316. As in FIG. 3, the water entering heat exchanger 3000
can be preheated
by a variety of hot fluids readily available at the pad, further improving
efficiency. The remainder
of FIG. 4 is similar to FIG. 3, having a number of heat exchangers (3040,
3050, 3060, 3530, 3550),
pumps (3540, 3510), air (312, 314) and fuel lines (311, 315), feedwater lines
(306 (e.g., from
evaporators), 307, 308, 309), separators (3520, 3070), blowdown water line 310
(e.g., from
reservoir), produced gas line 305, produced liquid line 303 (comprising for
example
bitumen/water) and drum boiler 3500 which accepts the remotely preheated water
as a boiler
feedwater, and uses burner 3560 to produce the hot gas that turns the heated
feedwater to steam
and is exhausted via line 313.
13
Date Recue/Date Received 2023-01-05
